Anti-gas-cut drilling fluid composite temporary plugging agent and application thereof

Abstract

The invention provides an anti-gas-cut drilling fluid composite temporary plugging agent and application thereof.The anti-gas-cut drilling fluid composite temporary plugging agent is prepared from hydroxyapatite, calcium carbonate and graphite, the hydroxyapatite, the calcium carbonate and the graphite are divided into a first layer, a second layer, a third layer and a fourth layer according to the particle size from large to small for particle size grading, and the first layer, the second layer, the third layer and the fourth layer are subjected to particle size grading; the particle size of hydroxyapatite is located at a first level, the particle sizes of hydroxyapatite and calcium carbonate are located at a second level, and the particle size of calcium carbonate is located at a third level; the particle size of graphite is at the fourth level; the mass ratio of the components with the particle sizes in the first level, the second level, the third level and the fourth level is (3-4): (4-5): (5-7): (1-3). Through the grain size grading design of the temporary plugging agent, an efficient and compact temporary plugging layer is formed on the surface of a well wall, gas in a stratum is prevented from invading a shaft, the acid solubility of the temporary plugging agent is larger than 75%, the plugging layer can be removed through an acidic working solution during well completion or yield increase, and reservoir damage is avoided.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of drilling technology in petroleum industry, in particular to a drilling fluid composite temporary plugging agent and application. BACKGROUND

[0002] In the process of drilling operation, a certain amount of temporary plugging agent is usually added in the drilling fluid when the oil and gas layer is opened, the purpose is to form a temporary plugging layer on the well wall surface of the reservoir section, to reduce the reservoir damage caused by the invasion of harmful solid phase and filtrate in the drilling fluid into the reservoir. After the drilling operation is completed, certain measures need to be taken to remove the temporary plugging layer to avoid plugging the oil and gas seepage channel and affecting the subsequent oil and gas production. Therefore, the temporary plugging agent currently used usually requires to have acid solubility, mostly using calcium carbonate, which can be dissolved in the acid working fluid used in the completion operation or the acidizing fluid used in the acidizing action, so as to remove the temporary plugging layer and avoid reservoir damage.

[0003] In order to quickly and effectively form a temporary plugging layer in the drilling process and improve the pressure-bearing effect of the temporary plugging layer, the petroleum industry has carried out a lot of research on the particle size grading design of the temporary plugging agent, and has put forward various particle size grading rules of the temporary plugging agent, including "1 / 3 rule", "2 / 3 rule", D90 rule, etc. According to the "1 / 3 rule", the D50 value of the bridging agent should be equal to or slightly greater than one third of the median pore size of the formation; according to the "2 / 3 rule", the median particle size of the bridging agent should be equal to or slightly greater than two thirds of the median pore size of the formation. These two rules only recommend the median particle size that can play a bridging role, without limiting the particle size distribution, upper and lower limits, etc. of all temporary plugging agent particles, resulting in large randomness of the temporary plugging agent particle size grading design and difficulty in quantification. The D90 rule and the ideal filling rule formed on the basis thereof require that when the D90 value of the temporary plugging agent particles on the particle size cumulative distribution curve is equal to the maximum pore throat diameter or the maximum fracture width of the oil and gas layer, the ideal temporary plugging effect can be achieved.

[0004] In the drilling operation of the natural gas containing reservoir section, due to the existence of fractures in the formation, the high pressure natural gas in the reservoir will invade into the wellbore under the action of pressure difference, gas invasion occurs, and the gas rises rapidly to the wellhead in the wellbore. If the gas invasion amount is large, it will further cause well kick or even blowout disaster. Therefore, it is necessary to prevent or reduce gas invasion through adjustment of working construction parameters or optimization of drilling fluid components. In theory, the use of drilling fluid temporary plugging agent to form a high-efficiency temporary plugging layer in the fracture under the positive pressure difference of the wellbore is expected to resist the invasion of gas in the formation into the formation. However, the sealing of the fracture by the drilling fluid to prevent the invasion of the gas in the formation into the wellbore and the sealing of the fracture to prevent the drilling fluid from entering the formation are two completely different processes, but the temporary plugging agent and the particle size grading rule currently researched at home and abroad are all aimed at the sealing of the fracture to prevent the invasion of the drilling fluid into the reservoir during the drilling process, rather than the process of the reverse invasion of the gas in the reservoir into the drilling fluid, and there is no suitable drilling fluid temporary plugging agent and particle size grading design rule for sealing the fracture to prevent gas invasion. SUMMARY

[0005] In view of this, the present application provides a gas invasion prevention drilling fluid composite temporary plugging agent and application, aiming at solving the problem that the phenomenon of gas reverse invasion of drilling fluid in the reservoir in the prior art cannot be effectively controlled.

[0006] The first aspect of the present application provides a gas invasion prevention drilling fluid composite temporary plugging agent, comprising the following components: hydroxyapatite, calcium carbonate and graphite, wherein the hydroxyapatite, calcium carbonate and graphite are divided into first level, second level, third level and fourth level for particle size grading according to particle size from large to small, wherein the particle size of the hydroxyapatite is in the first level, the particle size of the hydroxyapatite and the calcium carbonate is in the second level, and the particle size of the calcium carbonate is in the third level; the particle size of the graphite is in the fourth level; the mass ratio of the components in the first level, the second level, the third level and the fourth level is 3-4:4-5:5-7:1-3.

[0007] Further, in the above-mentioned gas invasion prevention drilling fluid composite temporary plugging agent, the mass ratio of the hydroxyapatite and the calcium carbonate in the second level is 5-6:4-5.

[0008] Further, in the above-mentioned gas invasion prevention drilling fluid composite temporary plugging agent, the maximum particle size of the components in the first level is 0.8-1.0 times the maximum opening of the formation fracture; the D50 particle size value of the components in the first level is 0.6-0.8 times the average opening of the formation fracture, and the minimum diameter of the particles of the components in the first level is 0.44-0.5 times the average opening of the fracture.

[0009] Further, in the above-mentioned gas invasion prevention drilling fluid composite temporary plugging agent, the minimum diameter of the particles of the components in the first level is 0.5 times the average opening of the fracture.

[0010] Further, in the above-mentioned gas invasion prevention drilling fluid composite temporary plugging agent, the maximum particle size of the components in the second level is 0.5-0.7 times the maximum opening of the formation fracture; the D50 particle size value of the components in the second level is 0.5-0.58 times the average opening of the formation fracture, and the minimum diameter of the particles of the components in the second level is 0.4-0.42 times the average opening of the fracture.

[0011] Further, in the above-mentioned gas invasion prevention drilling fluid composite temporary plugging agent, the minimum diameter of the particles of the components in the second level is 0.4 times the average opening of the fracture.

[0012] Further, in the above-mentioned gas invasion prevention drilling fluid composite temporary plugging agent, the D50 particle size value of the components in the third level is 0.4-0.48 times the average opening of the formation fracture, and the minimum diameter of the particles of the components in the third level is 0.25-0.38 times the average opening of the fracture.

[0013] Further, in the gas invasion preventing drilling fluid composite temporary plugging agent, the D50 particle size value of the component in the fourth level is 0.2-0.38 times the average opening of the formation fracture, and the minimum diameter of the particles of the component in the fourth level is 0.15-0.24 times the average opening of the fracture.

[0014] The second aspect of the application provides an application of a temporary plugging agent in preventing gas in a reservoir from invading a drilling fluid, characterized in that after 6-10% of the composite temporary plugging agent by mass fraction is added to the drilling fluid, a surface treatment agent is added, and the mass ratio of the surface treatment agent to the composite temporary plugging agent is 1-2:65-160.

[0015] Further, in the application, the surface treatment agent is at least one of disodium ethylenetriamine pentamethylene phosphonate, penta-sodium ethylenetriamine pentamethylene phosphonate and tetra-sodium amino trimethylene phosphonate.

[0016] The gas invasion preventing drilling fluid composite temporary plugging agent provided by the application is divided into four levels from large to small in particle size, the hydroxyapatite with the particle size in the first level is used to quickly form a basic skeleton of the plugging layer, the mixture of the hydroxyapatite and the calcium carbonate with the particle size in the second level is used to fill large pores on the basis of the basic skeleton of the plugging layer and consolidate the basic skeleton of the plugging layer, the calcium carbonate with the particle size in the third level is used to further fill medium-small pores in the plugging layer, and the graphite with the particle size in the fourth level is used to further squeeze and fill small pores in the plugging layer to form a dense plugging layer, which is conducive to forming a high-efficiency dense temporary plugging layer on the surface of the well wall, preventing gas in the formation from invading the wellbore, improving the safety factor of drilling operations, and the acid solubility of the temporary plugging agent is greater than or equal to 75%, the plugging layer can be removed by an acidic working fluid during well completion or production increase, reservoir damage is avoided, and the production capacity is fully released. DETAILED DESCRIPTION

[0017] To make the object, technical scheme and advantages of the application more clear, the embodiments of the application will be further described in detail below.

[0018] During drilling operations, high-pressure gas invasion in the reservoir section is easy to invade the wellbore, causing gas invasion, well kick and even blowout accidents. The temporary plugging agents and particle size grading rules researched at home and abroad at present are all aimed at plugging fractures to prevent drilling fluid from invading the reservoir during drilling, rather than at the process of gas in the reservoir invading the drilling fluid in the opposite direction. In view of the gas invasion problem in the process of drilling in the fractured gas reservoir, it is of great significance to explore and research a temporary plugging agent and a particle size grading design method for efficiently plugging fractures to prevent gas in the formation from invading the wellbore, taking into account the acid solubility to ensure effective removal of the plugging layer in subsequent well completion and production increase operations, effectively protecting the reservoir while efficiently preventing and treating gas invasion in drilling in the fractured gas reservoir and ensuring the safety of drilling operations.

[0019] The application forms a blocking layer basic framework by taking hydroxyapatite as the first level, fills large pores on the basis of the basic framework by taking hydroxyapatite and calcium carbonate as the second level, further fills the medium-small pores in the blocking layer on the basis of the blocking layer framework formed by the first and second levels by taking calcium carbonate as the third level, further extrudes and fills the small pores in the blocking layer by using elastic particles on the basis of the blocking layer framework formed by the first, second and third levels by taking graphite as the fourth level, forms a dense blocking layer, can make the drilling fluid form an efficient blocking layer in the fracture, effectively prevents gas invasion, and the acid-soluble rate of the temporary plugging agent is greater than or equal to 75%, can ensure that the main structure of the blocking layer is dissolved by an acidic working fluid, is damaged and removed in subsequent well completion and stimulation operations, thereby removing the plugging of the reservoir fracture by the temporary plugging agent and avoiding the damage of the reservoir to the subsequent natural gas production.

[0020] The drilling fluid composite temporary plugging agent of the embodiment of the application comprises the following components: hydroxyapatite, calcium carbonate and graphite, wherein the hydroxyapatite, calcium carbonate and graphite are classified into a first level, a second level, a third level and a fourth level according to the particle size from large to small, wherein the particle size of the hydroxyapatite is in the first level, the particle size of the hydroxyapatite and calcium carbonate is in the second level, and the particle size of the calcium carbonate is in the third level; the particle size of the graphite is in the fourth level; and the mass ratio of the components in the first level, the second level, the third level and the fourth level is 3-4:4-5:5-7:1-3.

[0021] Preferably, in the second level, the mass ratio of the hydroxyapatite and calcium carbonate is 5-6:4-5.

[0022] More specifically, the maximum particle size of the components in the first level is 0.8-1.0 times the maximum opening of the formation fracture; the D50 particle size value of the components in the first level is 0.6-0.8 times the average opening of the formation fracture, and the minimum diameter of the particles of the components in the first level is 0.44-0.5 times the average opening of the fracture. Preferably, the minimum diameter of the particles of the components in the first level is 0.5 times the average opening of the fracture.

[0023] The maximum particle size of the components in the second level is 0.5-0.7 times the maximum opening of the formation fracture; the D50 particle size value of the components in the second level is 0.5-0.58 times the average opening of the formation fracture, and the minimum diameter of the particles of the components in the second level is 0.4-0.42 times the average opening of the fracture. Preferably, the minimum diameter of the particles of the components in the second level is 0.4 times the average opening of the fracture.

[0024] The D50 particle size value of the components in the third level is 0.4-0.48 times the average opening of the formation fracture, and the minimum diameter of the particles of the components in the third level is 0.25-0.38 times the average opening of the fracture.

[0025] The D50 particle size value of the component in the fourth level is 0.2-0.38 times the average opening of the formation fracture, and the minimum diameter of the particles in the fourth level is 0.15-0.24 times the average opening of the fracture.

[0026] In the embodiment, the first level of the drilling fluid composite temporary plugging agent uses hydroxyapatite, which is acid-soluble and has a higher density than calcium carbonate, and can contact and stay at the lower end of the fracture faster under the action of gravity, and can extrude to form the basic framework of the plugging layer, that is, the hydroxyapatite in the first level is used to quickly form the basic framework of the plugging layer.

[0027] The second level of the drilling fluid composite temporary plugging agent is composed of hydroxyapatite and calcium carbonate in a mass ratio of 5-6:4-5, and fills large pores on the basis of the basic framework of the plugging layer formed by the first level, and consolidates the basic framework of the plugging layer.

[0028] The third level of the drilling fluid composite temporary plugging agent uses calcium carbonate to further fill the medium-small pores in the plugging layer on the basis of the plugging layer framework formed by the first and second levels.

[0029] The fourth level of the drilling fluid composite temporary plugging agent uses graphite to further extrude and fill the small pores in the plugging layer using elastic particles on the basis of the plugging layer framework formed by the first, second and third levels, and forms a dense plugging layer.

[0030] On the other hand, the application also provides an application of the drilling fluid temporary plugging agent in preventing gas in the reservoir from invading the drilling fluid in the reverse direction, which comprises: after adding the composite temporary plugging agent with a mass fraction of 6-10% into the drilling fluid, adding a surface treatment agent, and the mass ratio of the surface treatment agent to the composite temporary plugging agent is 1-2:65-160.

[0031] In the embodiment, after the composite temporary plugging agent is added to the drilling fluid, the surface treatment agent is added, which is beneficial to ensuring the dispersion stability of the composite temporary plugging agent in the drilling fluid.

[0032] The surface treatment agent comprises at least one of disodium ethylenetriamine pentamethylene phosphonate, penta-sodium ethylenetriamine pentamethylene phosphonate and tetra-sodium aminotri-methylene phosphonate.

[0033] The hydroxyapatite and calcium carbonate used in the drilling fluid composite temporary plugging agent provided in the embodiment are both acid-soluble materials, and the hydroxyapatite can form phosphoric acid and calcium salt in the acid solution, so that the acid-soluble rate of the temporary plugging agent is greater than or equal to 75%. For example, in the HCl solution, the acid-soluble rate can be divided into four steps, and the equation is as follows:

[0034] Ca 10 (PO4)6(OH)2+2HCl=3Ca3(PO4)2+CaCl2+2H2O

[0035] Ca3(PO4)2+ 2HCl = 2CaHPO4+ CaCl2

[0036] 2CaHPO4+ 2HCl = Ca(H2PO4)2+ CaCl2

[0037] Ca(H2PO4)2+ 2HCl = 2H3PO4+ CaCl2

[0038] Calcium carbonate can react in hydrochloric acid to form calcium chloride, water and carbon dioxide, the equation is:

[0039] CaCO3+ 2HCl = CaCl2+ H2O + CO2

[0040] The composite temporary plugging agent of the embodiment of the present application has an acid solubility of ≥75% when immersed in a hydrochloric acid solution with a concentration of ≥5% for 8 hours.

[0041] From the above, it can be seen that the drilling fluid composite temporary plugging agent in the embodiment of the present application can form a high-efficiency plugging layer in the fractures of the drilling fluid, effectively preventing gas invasion, and the acid solubility of the temporary plugging agent is ≥75%, which can ensure that the main structure of the plugging layer is dissolved by an acidic working fluid, damaged and removed in subsequent well completion and stimulation operations, thereby removing the plugging of the temporary plugging agent to the fractures of the reservoir and avoiding reservoir damage affecting the subsequent production of natural gas.

[0042] The drilling fluid temporary plugging agent provided by the embodiment of the present application is suitable for use in natural gas reservoir drilling operations, and through the design of the type, amount and particle size grading of the drilling fluid temporary plugging agent, a high-efficiency and dense temporary plugging layer can be formed on the surface of the well wall to prevent gas in the formation from invading the wellbore, improve the safety factor of drilling operations, and the acid solubility of the temporary plugging agent is ≥75%, which can remove the plugging layer by an acidic working fluid during well completion or stimulation, avoid reservoir damage, and fully release the production capacity.

[0043] The composite temporary plugging agent, the preparation method and the application thereof provided by the present application will be described in detail below in combination with embodiments, but they should not be understood as limiting the scope of protection of the present application.

[0044] The drilling fluid formula used to evaluate the performance of the drilling fluid composite temporary plugging agent prepared in each embodiment includes the following components in mass parts:

[0045] Water 100 parts, xanthan gum 0.2 parts, polypropylene fiber 0.2 parts.

[0046] Evaluation experimental method: (1) using long fracture plugging simulation experimental device, simulating wedge-shaped fracture in actual formation, experimentally evaluating the effect of reverse pressure-bearing plugging gas invasion after the plugging layer formed by the embodiment of the application in the wedge-shaped fracture, the size of the wedge-shaped fracture module used is 1x0.5mm and 2x1mm, i.e. the opening of the fracture opening end is 1mm and 2mm, the opening of the fracture end is 0.5mm and 1mm, and the length of the fracture is 1m. (2) soaking the composite temporary plugging agent of the application in 5% hydrochloric acid solution for 8h, and calculating the acid solubility according to the mass change before and after soaking.

[0047] Examples 1-3 and Comparative Examples 1-3 are for 1x0.5mm wedge-shaped fracture, the maximum opening of the fracture is 1mm, the minimum opening is 0.5mm, and the average opening is 0.75mm. The selected comparative examples are to use calcium carbonate, the most commonly used temporary plugging agent in the current oil industry, and the particle size design criteria are to select three typical temporary plugging agent particle size grading criteria, i.e. "1 / 3 criterion", "2 / 3 criterion" and "D90 criterion".

[0048] Example 1

[0049] The drilling fluid composite temporary plugging agent is prepared, the particle size of the hydroxyapatite is in the first level, the particle size of the hydroxyapatite and the calcium carbonate is in the second level, and the particle size of the calcium carbonate is in the third level; the particle size of the graphite is in the fourth level; and the mass ratio of the components with particle sizes in the first level, the second level, the third level and the fourth level is 3:4:5:1;

[0050] The first level is hydroxyapatite, the maximum particle diameter of which is 0.8 times the maximum opening of the formation fracture, i.e. 0.8mm; the D50 value is 0.6 times the average opening of the formation fracture, i.e. 0.45mm; and the minimum diameter is 0.5 times the average opening of the fracture, i.e. 0.375mm;

[0051] The second level is hydroxyapatite and calcium carbonate, which is composed of 5:4 in mass ratio, the maximum particle diameter of which is 0.5 times the maximum opening of the formation fracture, i.e. 0.5mm; the D50 value is 0.5 times the average opening of the formation fracture, i.e. 0.375mm; and the minimum diameter is 0.42 times the average opening of the fracture, i.e. 0.3mm;

[0052] The third level is calcium carbonate, the D50 value of which is 0.4 times the average opening of the formation fracture, i.e. 0.3mm; and the minimum diameter is 0.25 times the average opening of the formation fracture, i.e. 0.1875mm;

[0053] The fourth level is graphite, the D50 value of which is 0.2 times the average opening of the formation fracture, i.e. 0.15mm; and the minimum diameter is 0.15 times the average opening of the formation fracture, i.e. 0.1125mm.

[0054] The mass fraction of the drilling fluid composite temporary plugging agent used in the drilling fluid is 6%.

[0055] To ensure the dispersion stability of the drilling fluid composite temporary plugging agent in the drilling fluid, after the composite temporary plugging agent is added to the drilling fluid, ethylenediamine tetramethylene phosphonic acid disodium is added, and the mass ratio of the ethylenediamine tetramethylene phosphonic acid disodium to the composite temporary plugging agent is 1:65.

[0056] Example 2

[0057] The drilling fluid composite temporary plugging agent is prepared, the particle size of the hydroxyapatite is in the first level, the particle size of the hydroxyapatite and the calcium carbonate is in the second level, and the particle size of the calcium carbonate is in the third level; the particle size of the graphite is in the fourth level; and the mass ratio of the components with particle sizes in the first level, the second level, the third level and the fourth level is 4:5:7:3.

[0058] The first level is the hydroxyapatite, the maximum particle diameter of which is 1 times of the maximum opening of the formation fracture, i.e. 1.0 mm; the D50 value is 0.8 times of the average opening of the formation fracture, i.e. 0.6 mm; and the minimum diameter is 0.5 times of the average opening of the formation fracture, i.e. 0.375 mm.

[0059] The second level is the hydroxyapatite and the calcium carbonate which are composed according to the mass ratio of 6:5, the maximum particle diameter of which is 0.7 times of the maximum opening of the formation fracture, i.e. 0.7 mm; the D50 value is 0.58 times of the average opening of the formation fracture, i.e. 0.45 mm; and the minimum diameter is 0.4 times of the average opening of the formation fracture, i.e. 0.3 mm.

[0060] The third level is the calcium carbonate, the D50 value of which is 0.48 times of the average opening of the formation fracture, i.e. 0.375 mm; and the minimum diameter is 0.38 times of the average opening of the formation fracture, i.e. 0.3 mm.

[0061] The fourth level is the graphite, the D50 value of which is 0.38 times of the average opening of the formation fracture, i.e. 0.3 mm; and the minimum diameter is 0.24 times of the average opening of the formation fracture, i.e. 0.1875 mm.

[0062] The mass fraction of the drilling fluid composite temporary plugging agent used in the drilling fluid is 8%. To ensure the dispersion stability of the composite temporary plugging agent in the drilling fluid, after the composite temporary plugging agent is added to the drilling fluid, aminotrimethylene phosphonic acid tetrasodium is added, and the mass ratio of the aminotrimethylene phosphonic acid tetrasodium to the composite temporary plugging agent is 1:75.

[0063] Example 3

[0064] The particle size of the hydroxyapatite is in the first level, the particle size of the hydroxyapatite and the calcium carbonate is in the second level, and the particle size of the calcium carbonate is in the third level; the particle size of the graphite is in the fourth level; and the mass ratio of the components in the first level, the second level, the third level and the fourth level is 3:5:6:2 respectively.

[0065] The first level is the hydroxyapatite, the maximum particle diameter of which is 0.9 times the maximum opening of the formation fracture, i.e. 0.9 mm; the D50 value is 0.7 times the average opening of the formation fracture, i.e. 0.525 mm; and the minimum diameter is 0.5 times the average opening of the formation fracture, i.e. 0.375 mm.

[0066] The second level is the hydroxyapatite and the calcium carbonate, which are composed according to a mass ratio of 1:1, the maximum particle diameter of which is 0.6 times the maximum opening of the formation fracture, i.e. 0.6 mm; the D50 value is 0.5 times the average opening of the formation fracture, i.e. 0.375 mm; and the minimum diameter is 0.4 times the average opening of the formation fracture, i.e. 0.3 mm.

[0067] The third level is the calcium carbonate, the D50 value of which is 0.4 times the average opening of the formation fracture, i.e. 0.3 mm; and the minimum diameter is 0.3 times the average opening of the formation fracture, i.e. 0.1875 mm.

[0068] The fourth level is the graphite, the D50 value of which is 0.2 times the average opening of the formation fracture, i.e. 0.15 mm; and the minimum diameter is 0.15 times the average opening of the formation fracture, i.e. 0.1125 mm.

[0069] The mass fraction of the drilling fluid composite temporary plugging agent used in the drilling fluid is 10%.

[0070] In order to ensure the dispersion stability of the drilling fluid composite temporary plugging agent in the drilling fluid, after the composite temporary plugging agent is added to the drilling fluid, ethylenediamine pentamethylene phosphonic acid pentasodium is added, and the mass ratio of the ethylenediamine pentamethylene phosphonic acid pentasodium to the composite temporary plugging agent is 1:65.

[0071] Comparative Example 1

[0072] The temporary plugging agent is calcium carbonate, and the mass fraction used in the drilling fluid is 6% according to the 1 / 3 rule design for 1x0.5mm fracture.

[0073] Comparative Example 2

[0074] The temporary plugging agent is calcium carbonate, and the mass fraction used in the drilling fluid is 8% according to the 2 / 3 rule design for 1x0.5mm fracture.

[0075] Comparative Example 3

[0076] The temporary plugging agent is calcium carbonate, and the mass fraction used in the drilling fluid is 10% according to the D90 criterion for a 1*0.5mm fracture.

[0077] Examples 4-6 and Comparative Examples 4-6 are for a 2*1mm wedge-shaped fracture with a maximum opening of 2mm, a minimum opening of 1mm, and an average opening of 1.5mm.

[0078] Example 4

[0079] The drilling fluid composite temporary plugging agent is prepared, the particle size of the hydroxyapatite is in the first level, the particle size of the hydroxyapatite and the calcium carbonate is in the second level, and the particle size of the calcium carbonate is in the third level; the particle size of the graphite is in the fourth level; and the mass ratio of the components with particle sizes in the first level, the second level, the third level and the fourth level is 4:4:5:2.

[0080] The first level is hydroxyapatite, the maximum particle diameter of which is 0.8 times the maximum opening of the formation fracture, i.e. 1.6mm; the D50 value is 0.6 times the average opening of the formation fracture, i.e. 0.9mm; and the minimum diameter is 0.5 times the average opening of the fracture, i.e. 0.75mm.

[0081] The second level is hydroxyapatite and calcium carbonate in a mass ratio of 5:4, the maximum particle diameter of which is 0.5 times the maximum opening of the formation fracture, i.e. 1mm; the D50 value is 0.5 times the average opening of the formation fracture, i.e. 0.75mm; and the minimum diameter is 0.4 times the average opening of the fracture, i.e. 0.6mm.

[0082] The third level is calcium carbonate, the D50 value of which is 0.4 times the average opening of the formation fracture, i.e. 0.6mm; and the minimum diameter is 0.25 times the average opening of the formation fracture, i.e. 0.375mm.

[0083] The fourth level is graphite, the D50 value of which is 0.2 times the average opening of the formation fracture, i.e. 0.3mm; and the minimum diameter is 0.15 times the average opening of the formation fracture, i.e. 0.225mm.

[0084] The mass fraction of the drilling fluid composite temporary plugging agent used in the drilling fluid is 6%.

[0085] In order to ensure the dispersion stability of the drilling fluid composite temporary plugging agent in the drilling fluid, after the composite temporary plugging agent is added to the drilling fluid, pentasodium aminotrimethylene phosphonate is added, and the mass ratio of the pentasodium aminotrimethylene phosphonate to the composite temporary plugging agent is 2:155.

[0086] Example 5

[0087] The drilling fluid composite temporary plugging agent is prepared, the particle size of the hydroxyapatite is in the first level, the particle size of the hydroxyapatite and the calcium carbonate is in the second level, and the particle size of the calcium carbonate is in the third level; the particle size of the graphite is in the fourth level; and the mass ratio of the components with the particle sizes in the first level, the second level, the third level and the fourth level is 4:5:7:3.

[0088] The first level is the hydroxyapatite, the maximum particle diameter of which is 1 times of the maximum opening of the formation fracture, i.e. 2 mm; the D50 value is 0.8 times of the average opening of the formation fracture, i.e. 1.2 mm; and the minimum diameter is 0.5 times of the average opening of the fracture, i.e. 0.75 mm.

[0089] The second level is the hydroxyapatite and the calcium carbonate which are composed according to the mass ratio of 6:5, the maximum particle diameter of which is 0.7 times of the maximum opening of the formation fracture, i.e. 1.4 mm; the D50 value is 0.58 times of the average opening of the formation fracture, i.e. 0.9 mm; and the minimum diameter is 0.4 times of the average opening of the fracture, i.e. 0.6 mm.

[0090] The third level is the calcium carbonate, the D50 value of which is 0.48 times of the average opening of the formation fracture, i.e. 0.75 mm; and the minimum diameter is 0.38 times of the average opening of the formation fracture, i.e. 0.6 mm.

[0091] The fourth level is the graphite, the D50 value of which is 0.38 times of the average opening of the formation fracture, i.e. 0.6 mm; and the minimum diameter is 0.24 times of the average opening of the formation fracture, i.e. 0.375 mm.

[0092] The mass fraction of the composite temporary plugging agent used in the drilling fluid is 8%.

[0093] In order to ensure the dispersion stability of the drilling fluid composite temporary plugging agent in the drilling fluid, after the composite temporary plugging agent is added to the drilling fluid, ethylenediamine pentamethylene phosphonic acid pentasodium is added, and the mass ratio of the ethylenediamine pentamethylene phosphonic acid pentasodium to the composite temporary plugging agent is 1:110.

[0094] Example 6

[0095] The drilling fluid composite temporary plugging agent is prepared, the particle size of the hydroxyapatite is in the first level, the particle size of the hydroxyapatite and the calcium carbonate is in the second level, and the particle size of the calcium carbonate is in the third level; the particle size of the graphite is in the fourth level; and the mass ratio of the components with the particle sizes in the first level, the second level, the third level and the fourth level is 3:5:6:2.

[0096] The first level is the hydroxyapatite, the maximum particle diameter of which is 0.9 times of the maximum opening of the formation fracture, i.e. 1.8 mm; the D50 value is 0.7 times of the average opening of the formation fracture, i.e. 1.05 mm; and the minimum diameter is 0.5 times of the average opening of the fracture, i.e. 0.75 mm.

[0097] The second layer is hydroxyapatite and calcium carbonate with a mass ratio of 1:1, the maximum particle diameter of which is 0.6 times the maximum opening of the formation fracture, i.e. 0.6 mm; the D50 value is 0.58 times the average opening of the formation fracture, i.e. 0.9 mm; and the minimum diameter is 0.42 times the average opening of the formation fracture, i.e. 0.3 mm;

[0098] The third layer is calcium carbonate with a D50 value of 0.4 times the average opening of the formation fracture, i.e. 0.6 mm; and a minimum diameter of 0.25 times the average opening of the formation fracture, i.e. 0.375 mm.

[0099] The fourth layer is graphite with a D50 value of 0.3 times the average opening of the formation fracture, i.e. 0.45 mm; and a minimum diameter of 0.15 times the average opening of the formation fracture, i.e. 0.225 mm.

[0100] The mass fraction of the composite bridging agent used in the drilling fluid is 10%.

[0101] In order to ensure the dispersion stability of the composite bridging agent in the drilling fluid, after the composite bridging agent is added to the drilling fluid, tetrasodium amino-tris(methylene phosphonate) is added, and the mass ratio of the tetrasodium amino-tris(methylene phosphonate) to the composite bridging agent is 2:160.

[0102] Comparative Example 4

[0103] The bridging agent is calcium carbonate, and for a 2x1 mm fracture, the design is according to the 1 / 3 rule, and the mass fraction used in the drilling fluid is 6%.

[0104] Comparative Example 5

[0105] The bridging agent is calcium carbonate, and for a 2x1 mm fracture, the design is according to the 2 / 3 rule, and the mass fraction used in the drilling fluid is 8%.

[0106] Comparative Example 6

[0107] The bridging agent is calcium carbonate, and for a 2x1 mm fracture, the design is according to the D90 rule, and the mass fraction used in the drilling fluid is 10%.

[0108] The above-mentioned example numbers of the present application are only for description, and do not represent the advantages and disadvantages of the examples. In the examples of the present application, only the fractures with sizes of 1x0.5 mm and 2x1 mm are taken as examples for description, and should not be understood as a limitation on the application range of the examples of the present application. The drilling fluid bridging agent of the present application is suitable for any size of fracture.

[0109] The reverse plugging gas invasion pressure-bearing capacity of Examples 1-3 and Comparative Examples 1-3 for a 1x0.5 mm fracture is shown in Table 1.

[0110] Table 1 Reverse plugging pressure-bearing capacity of adding the bridging agent of different examples to a 1x0.5 mm fracture

[0111] Test sample Pressure resistance / MPa Example 1 1.39 Example 2 1.64 Example 3 1.90 Comparative Example 1 1.06 Comparative Example 2 1.30 Comparative Example 3 1.55

[0112] It can be seen that the plugging pressure-bearing capacity of the three embodiments of the present application is higher than that of the three comparative examples. When the mass fraction of the temporary plugging agent in the drilling fluid is 6%, the pressure-bearing capacity of embodiment 1 is 0.33 MPa higher than that of comparative example 1, which increases by 31.13%; when the mass fraction of the temporary plugging agent in the drilling fluid is 8%, the pressure-bearing capacity of embodiment 2 is 0.34 MPa higher than that of comparative example 2, which increases by 26.15%; when the mass fraction of the temporary plugging agent in the drilling fluid is 10%, the pressure-bearing capacity of embodiment 3 is 0.35 MPa higher than that of comparative example 3, which increases by 22.58%.

[0113] The results show that for 1x0.5mm cracks, under the condition of the same amount of temporary plugging agent, the plugging pressure-bearing capacity of the temporary plugging agent of the embodiments of the present application is obviously higher than that of the temporary plugging agents prepared by using the three commonly used particle size grading rules of "1 / 3 rule", "2 / 3 rule" and "D90 rule". In addition, the acid dissolution rates of the composite temporary plugging agents of embodiments 1-3 in 5% hydrochloric acid solution after soaking for 8h are 88.21%, 79.25% and 83.17% respectively, which are relatively high, indicating that the composite temporary plugging agent can be effectively dissolved in the subsequent acidizing stimulation working fluid, thereby destroying the plugging layer and relieving the plugging of the reservoir, avoiding reservoir damage, and being beneficial to fully releasing the production capacity in the later period.

[0114] The pressure-bearing capacity of the embodiments and comparative examples against the reverse plugging of gas invasion into 2x1mm cracks is shown in Table 2.

[0115] Table 2 Reverse plugging pressure-bearing capacity of temporary plugging agents of different embodiments added into 2x1mm cracks

[0116] Test sample Pressure resistance / MPa Example 1 1.35 Example 2 1.55 Example 3 1.80 Comparative Example 1 1.05 Comparative Example 2 1.25 Comparative Example 3 1.49

[0117] It can be seen that the plugging pressure-bearing capacity of the three embodiments of the present application is higher than that of the three comparative examples. When the mass fraction of the temporary plugging agent in the drilling fluid is 6%, the pressure-bearing capacity of embodiment 1 is 0.33 MPa higher than that of comparative example 1, which increases by 31.13%; when the mass fraction of the temporary plugging agent in the drilling fluid is 8%, the pressure-bearing capacity of embodiment 2 is 0.34 MPa higher than that of comparative example 2, which increases by 26.15%; when the mass fraction of the temporary plugging agent in the drilling fluid is 10%, the pressure-bearing capacity of embodiment 3 is 0.35 MPa higher than that of comparative example 3, which increases by 22.58%.

[0118] The results show that, for the 2*1 mm crack, under the condition of the same amount of temporary plugging agent, the plugging pressure-bearing capacity of the temporary plugging agent of the embodiment is obviously higher than that of the temporary plugging agent prepared by using the three commonly used particle size grading rules of "1 / 3 rule", "2 / 3 rule" and "D90 rule". In addition, the acid dissolution rates of the composite temporary plugging agents of Examples 4-6 in 5% hydrochloric acid solution after soaking for 8h are 87.61%, 79.77% and 81.89% respectively, the acid dissolution rates are higher, indicating that the composite temporary plugging agent can be effectively dissolved in the subsequent acidizing stimulation working fluid, thereby destroying the plugging layer, releasing the plugging of the reservoir, avoiding the damage to the reservoir, and being beneficial to the full release of the production capacity in the later period.

[0119] The above merely describes the preferred embodiments of the present application, and is not intended to limit the present application. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present application shall be included in the protection scope of the present application.

Claims

1. A composite temporary plugging agent for drilling fluid used to prevent gas intrusion, characterized in that, The product comprises the following components: hydroxyapatite, calcium carbonate, and graphite. The hydroxyapatite, calcium carbonate, and graphite are graded according to their particle size from largest to smallest into four layers: a first layer, a second layer, a third layer, and a fourth layer. Specifically, the hydroxyapatite particles are in the first layer, the hydroxyapatite and calcium carbonate particles are in the second layer, the calcium carbonate particles are in the third layer, and the graphite particles are in the fourth layer. The mass ratio of the components in the first, second, third, and fourth layers is 3~4:4~5:5~7:1~3.

2. The gas intrusion prevention drilling fluid composite temporary plugging agent according to claim 1, characterized in that, In the second layer, the mass ratio of hydroxyapatite to calcium carbonate is 5~6:4~5.

3. The gas intrusion prevention drilling fluid composite temporary plugging agent according to claim 1, characterized in that, The maximum particle size of the component in the first layer is 0.8 to 1.0 times the maximum aperture of the formation fracture; the D50 particle size of the component in the first layer is 0.6 to 0.8 times the average aperture of the formation fracture; and the minimum particle diameter of the component in the first layer is 0.44 to 0.5 times the average aperture of the fracture.

4. The gas intrusion prevention drilling fluid composite temporary plugging agent according to claim 3, characterized in that, The minimum particle diameter of the component in the first level is 0.5 times the average crack aperture.

5. The gas intrusion prevention drilling fluid composite temporary plugging agent according to claim 1, characterized in that, The maximum particle size of the component in the second layer is 0.5 to 0.7 times the maximum aperture of the formation fracture; the D50 particle size of the component in the second layer is 0.5 to 0.58 times the average aperture of the formation fracture; and the minimum particle diameter of the component in the second layer is 0.4 to 0.42 times the average aperture of the fracture.

6. The gas intrusion prevention drilling fluid composite temporary plugging agent according to claim 5, characterized in that, The minimum particle diameter of the component in the second level is 0.4 times the average crack aperture.

7. The gas intrusion prevention drilling fluid composite temporary plugging agent according to claim 1, characterized in that, The D50 particle size of the components in the third layer is 0.4 to 0.48 times the average aperture of the formation fractures, and the minimum particle diameter of the components in the third layer is 0.25 to 0.38 times the average aperture of the fractures.

8. The gas intrusion prevention drilling fluid composite temporary plugging agent according to claim 1, characterized in that, The D50 particle size of the component in the fourth layer is 0.2 to 0.38 times the average aperture of the formation fracture, and the minimum particle diameter of the component in the fourth layer is 0.15 to 0.24 times the average aperture of the fracture.

9. The application of a temporary plugging agent as described in any one of claims 1-8 in preventing the reverse intrusion of gas from the reservoir into the drilling fluid, characterized in that, After adding a composite temporary plugging agent with a mass fraction of 6-10% to the drilling fluid, a surface treatment agent is added, wherein the mass ratio of the surface treatment agent to the composite temporary plugging agent is 1~2:65~160.

10. The application of the temporary plugging agent according to claim 9 in preventing the reverse intrusion of gas from the reservoir into the drilling fluid, characterized in that, The surface treatment agent is at least one of ethylenetriaminepentamethylenephosphonate disodium, ethylenetriaminepentamethylenephosphonate pentasodium, and aminotrimethylenephosphonate tetrasodium.